Separation of sulfurous materials

ABSTRACT

The present disclosure relates to systems and methods for separation of sulfurous material(s) from a multi-component feed stream. The systems and methods can comprise contacting the multi-component feed stream with a solvent in a contacting column so that at least a portion of the sulfurous material(s) is transferred from the multi-component feed stream to the solvent. A stream of a substantially purified gas can thus be provided along with a liquid stream comprising at least a majority of the sulfurous material. In particular, the solvent can comprise liquid carbon dioxide, which can be particularly beneficial for removing sulfurous materials from multi-component feed streams.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional PatentApplication No. 62/668,001, filed May 7, 2018, U.S. Provisional PatentApplication No. 62/685,724, filed Jun. 15, 2018, and U.S. ProvisionalPatent Application No. 62/696,938, filed Jul. 12, 2018, the disclosuresof which are incorporated herein by reference.

FIELD OF THE INVENTION

The present disclosure relates to separation of sulfurous materials frommixed streams, particularly gaseous streams. Separation can be carriedout utilizing systems and methods whereby the mixed stream is contactedwith a removal solvent, and particularly wherein the removal solventcomprises carbon dioxide.

BACKGROUND

Natural gas streams are often contaminated with one or more furthercomponents, such as sulfur compounds (e.g., hydrogen sulfide- or H₂S)and carbon dioxide (CO₂). In addition to containing methane (CH₄— or“C₁”), natural gas and associated natural gas streams often containsignificant quantities of longer chain hydrocarbons, such as ethane(C₂H₆— or “C₂”) and even higher carbon number hydrocarbons, include C₃and greater hydrocarbons. These higher number hydrocarbons can beseparated to provide valuable hydrocarbon streams, particularly uponremoval of contaminants, such as hydrogen sulfide and carbon dioxide. Asan example, natural gas stream sourced in Abu Dhabi can have anapproximate composition as follows (on a molar, water-free basis): 65%CH₄; 6.5% C₂H₆; 3% C₃H₈; 0.46% nC₄H₁₀; 0.54% C₄H₁₀; 0.4% C₅H₁₂; 0.1%C₆H₁₄; 16% H₂S; and 8% CO₂.

Current methods of removing H₂S and CO₂ from mixed gas streams, such asnatural gas streams, include: amine scrubbing; membrane treatment;adsorption on solid adsorbents; processing in low temperature separationsystems such as the Ryan-Holmes process (see U.S. Pat. No. 4,318,723),the Controlled-Freeze zone® process (see U.S. Pat. No. 8,312,738), andthe processes described in U.S. Pat. No. 9,945,605; and hybrid processesthat use a combination of any aforementioned methods, such as the hybridprocesses described in U.S. Pat. No. 8,955,354. These processes allinvolve high capital investments and high ongoing operating costs andinevitably lead to significant discharge of CO₂ to the atmosphere fromthe energy systems associated with them. If substantial amount of H₂S isavailable in the sour gas, cryogenic processes such as Ryan-Holmes orControlled-Freeze zone may not be economic, and conventional amineprocesses may be preferred due to overall lower costs. The use ofcryogenic natural gas sweetening process in the presence of high H₂Scontent would require an additional treatment step for removal of H₂Sfrom methane or ethane streams. This is due to inability of theseprocesses in confining the H₂S content of the feed stream as a singleproduct stream. For example, in the Ryan Holmes process the H₂S impurityin the sour gas feedstock is generally mixed with ethane product and afurther H₂S separation from ethane will be required. This condition mayfavor the use of a conventional amine plant for lower overall cost.Amine processes for high H₂S and/or CO₂ gas tend to be energy intensiveand have high investment and operating costs.

There remains a need in the art for lower cost, simpler processes thathave reduced emission or substantially zero emission of CO₂ into theatmosphere. The present disclosure thus relates to systems and methodswhereby CO₂ removed from natural gas (or another mixed gas stream)together along with CO₂ derived from an associated energy systemproviding power to the process preferably can be made available at highpressure with negligible hydrocarbon content for reinjection intogeologic formations or for other uses. The CO₂ stream further preferablycan be made available for enhanced oil recovery. The C₃ plushydrocarbons separated from the mixed gas stream preferably can beseparated with H₂S content (or other sulfurous material content) belowabout 2 ppm. The H₂S (or other sulfurous material) preferably can beseparated as a concentrated stream for use as a feed stream to a Claussulfur production plant, as feed to a sulfuric acid plant, and/or otherpotential uses. The H₂S containing stream or other sulfurous materialpreferably can be produced at high pressure for sequestration in ageologic formation such as a depleted gas or oil well. The natural gasstream (or other gas stream purified of at least a sulfurous material)preferably can have a sulfur content (such as an H₂S content) belowabout 2 ppm and a CO₂ content below about 2% by volume.

SUMMARY OF THE INVENTION

The present disclosure relates to systems and methods useful in theseparation of a sulfurous material from a mixed gaseous stream. Thesystems and methods particularly can be adapted to or configured tocontact the mixed gaseous steam comprising the sulfurous material with asolvent comprising one or more components suitable for removal of atleast a portion of the sulfurous material from the mixed gaseous stream.For example, in some embodiments, liquid carbon dioxide can beparticularly useful for selectively separating a wide variety of sulfurspecies from a mixed gaseous stream. The result is a substantiallypurified gas product and liquid stream that can be further processed asdesired. In some embodiments, a method for separating a sulfurousmaterial from a multi-component feed stream particularly can comprise:injecting a multi-component feed stream including at least a sulfurousmaterial and a fuel gas into a contacting column; injecting a solventstream comprising liquid carbon dioxide into the contacting column sothat the solvent stream comprising the liquid carbon dioxide contactsthe multi-component feed stream; withdrawing from the contacting columna bottom product stream containing at least a portion of the sulfurousmaterial from the multi-component feed stream; and withdrawing from thecontacting column an overhead vapor stream containing at least a portionof the fuel gas.

In one or more embodiments, the present disclosure relates to systemsand methods for separating and/or purifying various multi-component feedstreams, particularly separating sulfurous materials therefrom,utilizing carbon dioxide. The present disclosure provides a uniquelysimple and economic process to separate, for example, acidic impuritiessuch as sulfur compounds from fuel gas streams and/or othermulti-component feed streams. For example, fuel gas streams suitable foruse according to the present disclosure may be generated from variousprocesses such as oxy-fuel combustion and power generation, natural gasprocessing, and hydrogen generation. The presently disclosed systems andmethods are particularly useful when a relatively large amount ofhydrogen sulfide is present within the gaseous stream, and a source ofcarbon dioxide is readily available. The present process can operate attemperatures near the triple point of pure carbon dioxide (i.e., −56.4°C. at 5.2 bar), which eliminates the solidification of contaminants andthe need to process solid particles. The process has a simple layout andrequires a relatively small amount of electricity to generate requiredrefrigeration.

The present systems and methods are configured to generate a purifiedand substantially clean carbonaceous material (e.g., a fuel gas) streamfrom a multi-component feed stream including a sulfurous material usingrefrigeration and fractionation. The multi-component feed stream withthe sulfurous material can be cooled down to a temperature near the CO₂triple point and then treated in a suitable contacting column (e.g., amass transfer column or a distillation column) using liquid carbondioxide to generate a substantially sulfur free stream from the startingmaterial at overhead vapor and a sulfur enriched bottom product. Theprocess can be integrated with any chemical process that requiresclean-up of a process stream contaminated with sulfur species such ashydrogen sulfide. Carbon dioxide used in the scrubbing fluid canoriginate from a carbon dioxide containing stream within the integratedprocess or from an external source, and the carbon dioxide can besubstantially pure or may contain one or more contaminants. Thepresently disclosed systems and methods thus can be effective forseparating a carbonaceous stream (e.g., a fuel gas stream) fromcontaminating compounds (e.g., hydrogen sulfide, carbonyl sulfide,mercaptans, and other sulfur compounds with a condensation temperatureclose to that of hydrogen sulfide, and water vapor). For example, theprocess can include the use of a separation column system for processinga contaminated stream at a temperature close to the freezing point ofcarbon dioxide using liquid carbon dioxide solvent to producecontaminant-free overhead vapor and bottoms liquid product enriched insulfur-containing contaminants.

In further embodiments, the separation column can have a reboiler forboiling a portion of the sulfur-contaminants enriched bottoms liquid byindirect heat exchange against a cooling contaminated process stream toproduce cooled contaminated process stream fluid. Moreover, a heatexchanger can be used for cooling pure CO₂ using separation columnbottoms and overhead products by indirect heat exchange to producecondensed, pure carbon dioxide fluid. Still further, a first pressurereduction arrangement can be used for reducing the pressure of thecontaminated process stream to produce a reduced pressure, contaminatedprocess stream. Similarly, a second pressure reduction arrangement canbe used for expanding the contaminated process stream to reduce itstemperature to within about 5 ° C. of the freezing point of the CO₂(i.e., to a temperature of about −56.4 ° C.). In certain embodiments,the present disclosure particularly may provide a method of purificationof a process stream containing a sulfurous material, the methodcomprising passing the process stream containing the sulfurous through acontacting column (e.g., a mass transfer column) along with a stream ofa solvent comprising liquid carbon dioxide such that the process streamexiting the contacting column comprises a reduced level of the sulfurousmaterial.

In some embodiments, the present disclosure can particularly providemethods for separating a sulfurous material from a multi-component feedstream. For example, the method can comprise: injecting amulti-component feed stream including at least a sulfurous material anda fuel gas into a contacting column; injecting a solvent streamcomprising liquid carbon dioxide into the contacting column so that thesolvent stream comprising the liquid carbon dioxide contacts themulti-component feed stream; withdrawing from the contacting column abottom product stream containing at least a portion of the sulfurousmaterial from the multi-component feed stream; and withdrawing from thecontacting column an overhead vapor stream containing at least a portionof the fuel gas. In further embodiments, the method can be additionallydescribed in relation to one or more of the following statements, whichcan be combined in any number and order.

The method can comprise injecting the multi-component feed stream andthe solvent stream into the contacting column in a spatially separatedarrangement so that the solvent stream flows in a downwardly directionfor contacting the multi-component feed stream and the multi-componentfeed stream flows in an upwardly direction for contacting the solvent.

The contacting column can be a distillation column.

The contacting column can be a counter-current contacting column.

Prior to injecting of the multi-component feed stream into thecontacting column, the multi-component feed stream can comprise carbondioxide in an amount of at least 2% on a molar basis.

The sulfurous material in the multi-component feed stream can beselected from the group consisting of hydrogen sulfide, carbonylsulfide, thiol-containing compounds, and combinations thereof.

The multi-component feed stream injected into the contacting column canbe at a temperature of about −10° C. to about −55° C.

The solvent stream injected into the contacting column can be at atemperature of about −10° C. to about −55° C.

The contacting column can be operated under conditions such thatsubstantially no portion of any carbon dioxide in the contacting columnis solidified during passage through the contacting column.

The solvent stream injected into the contacting column can be at atemperature and pressure such that substantially all of the carbondioxide contained therein is in a liquid state.

The solvent stream injected into the contacting column can be at apressure of about 7 bar to about 100 bar.

Prior to the injecting steps, the method further can comprise passingone or both of the multi-component feed stream and the solvent streamthrough a heat exchanger against at least a portion of the overheadvapor stream that is withdrawn from the contacting column so that theoverhead vapor stream is heated and one or both of the multi-componentfeed stream and the solvent stream is cooled.

The method further can comprise evaporating one or more streams of aliquid refrigerant in the heat exchanger to maintain a heat balancethereof.

The one or more streams of liquid refrigerant can comprise liquid carbondioxide.

The overhead vapor stream withdrawn from the contacting column cancomprise less than 2% molar of the sulfurous material.

The overhead vapor stream withdrawn from the contacting column cancomprise less than 2 ppm molar of the sulfurous material.

The contacting column can be operated at a pressure of about 7 bar toabout 100 bar.

The contacting column can be configured for heat removal at one or morestages present in the contacting column at a position that is higher inthe contacting column than a position for the injecting of themulti-component feed stream.

The contacting column can comprise a re-boiler.

At least a portion of the multi-component feed stream can be passedthrough the re-boiler prior to said injecting into the contactingcolumn.

The method further can comprise passing the overhead vapor streamthrough a separation unit configured for removal of at least a portionof any carbon dioxide present in the overhead vapor stream.

The separation unit can be a membrane separator configured forseparating the overhead vapor stream into a product fuel gas stream anda permeate stream comprising at least carbon dioxide.

The product fuel gas stream can contain less than 2 ppm molar of thesulfurous material.

The product fuel gas stream can contain less than 2% molar of thesolvent.

The method further can comprise recycling at least a portion of thecarbon dioxide from the permeate stream to the solvent stream prior tosaid injecting of the solvent stream into the contacting column.

The method further can comprise passing the bottom product streamthrough one or more distillation columns configured for separating outone or more further components present in the bottom product stream inaddition to the sulfurous material.

The multi-component feed stream can be sour natural gas.

The bottom product stream can contain at least a portion of any hydrogensulfide and C₁ to C₅ hydrocarbons present in the sour natural gas.

The overhead vapor stream can contain a majority of methane present inthe sour natural gas.

At least a portion of the fuel gas in the overhead vapor stream can beprovided into a combustor of a power production unit.

A bottom liquid product stream from a first distillation column can beseparated in a second distillation column into a vapor overhead productstream containing preferably less than 2 ppm of sulfurous material and abottom liquid product stream containing preferably less than 10 ppmmethane.

The vapor overhead product stream preferably can contain less than 100ppm of C₃ and C₄ hydrocarbons.

A liquid bottom product stream from the second distillation column canbe separated in a third distillation column into a bottom hydrocarbonliquid product stream containing preferably less than 2 ppm sulfurousmaterial and a vapor overhead product stream containing substantiallyall of the remaining sulfurous material.

A feed stream to the third distillation column can be in the pressurerange of about 10 bar to about 20 bar.

A liquid hydrocarbon additive stream from an external source (or from arecycle stream) can be introduced into a top section of the seconddistillation column at a stage located between a feed stage and acondenser. The liquid hydrocarbon additive stream can comprise mainly C₄and greater hydrocarbons with a propane content less than about 2%molar.

A liquid hydrocarbon additive stream from an external source can beintroduced into a top section of the third distillation column at astage located between a feed stage and a condenser.

The liquid hydrocarbon additive stream can comprise mainly C₄ andgreater hydrocarbons with a propane content less than 2% molar.

A liquid bottom product from the third distillation column can beprocessed to separate C₄ and greater hydrocarbons as at least oneproduct and recycle at least a portion of the C₄ and greaterhydrocarbons back as a hydrocarbon additive stream to one or both of thesecond and third distillation columns.

The bottom liquid product from the first distillation column can containat least sufficient methane to ensure that greater than 75% molar andpreferably greater than 90% molar of any ethane in the bottom productfrom the first column can be separated as part of the overhead vaporstream from the second distillation column.

Additional carbon dioxide can be added to the bottom product from thefirst distillation column so that the combined carbon dioxide andmethane content of the bottom product from the first distillation columncan be sufficient to ensure that greater than 75% molar and preferablygreater than 90% molar of the ethane in the bottom product can beseparated as part of the overhead vapor stream from the second column.

The vapor overhead stream from the second distillation column at nearambient temperature can be passed into a second membrane carbon dioxideseparation unit to remove preferably at least 90% of the carbon dioxideprior to ethane separation.

The vapor overhead stream from the second distillation column can beintroduced to a fourth distillation column to which also a liquidhydrocarbon additive stream and/or a liquid hydrocarbon recycle streamcan be also introduced at a stage between a feed stage and a condensersuch that a vapor overhead stream enriched in carbon dioxide can bewithdrawn.

The liquid bottom product from the fourth distillation column can beintroduced into a fifth distillation column in which a vapor overheadstream enriched in ethane and a liquid bottom product enriched in liquidhydrocarbon compounds can be withdrawn.

The compressed carbon dioxide permeate stream from the membrane carbondioxide separator can be cooled to about −40° C. to about −55° C. andfed into a sixth distillation column in which a liquid bottom productenriched with carbon dioxide preferably with at least 80% molar purityand more preferably greater than 95% molar purity can be withdrawn.

The ambient temperature feed to the first membrane carbon dioxideseparator can comprise the vapor overhead streams from the first andsixth columns plus the compressed permeate stream from the secondmembrane unit.

In further embodiments, the present disclosure can particularly providesystems for use separating a sulfurous material from a multi-componentfeed stream. The systems can include a combination of components asdescribed herein, such as one or more contacting columns (e.g.,distillation columns), one or more heat exchangers, one or moreseparation membranes, one or more compressors, one or more driers, oneor more valves, and one or more lines for interconnecting the variouscomponents and providing for flow of various streams therethrough. Wherethe present disclosure describes the sulfur separation in relation tothe separation methods, it is understood that the components describedfor carrying out the method can be utilized in forming a system for usein carrying out the separation.

BRIEF DESCRIPTION OF THE DRAWINGS

Having thus described the disclosure in the foregoing general terms,reference will now be made to the accompanying drawings, which are notnecessarily drawn to scale, and wherein:

FIG. 1 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream according to embodiments ofthe present disclosure;

FIG. 2 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream according to furtherembodiments of the present disclosure;

FIG. 3 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream according to additionalembodiments of the present disclosure;

FIG. 4 is a flow diagram showing a system for separation of a sulfurousmaterial from a sour natural gas according to embodiments of the presentdisclosure;

FIG. 5 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream and processing the separatedsulfurous material according to embodiments of the present disclosure;

FIG. 6 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream and processing the separatedsulfurous material according to embodiments of the present disclosure;

FIG. 7 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream and processing the separatedsulfurous material according to embodiments of the present disclosure;and

FIG. 8 is a flow diagram showing a system for separation of a sulfurousmaterial from a multi-component feed stream and processing the separatedsulfurous material according to embodiments of the present disclosure.

DETAILED DESCRIPTION

The present subject matter will now be described more fully hereinafterwith reference to exemplary embodiments thereof. These exemplaryembodiments are described so that this disclosure will be thorough andcomplete, and will fully convey the scope of the subject matter to thoseskilled in the art. Indeed, the subject matter can be embodied in manydifferent forms and should not be construed as limited to theembodiments set forth herein; rather, these embodiments are provided sothat this disclosure will satisfy applicable legal requirements. As usedin the specification, and in the appended claims, the singular forms“a”, “an”, “the”, include plural referents unless the context clearlydictates otherwise.

The present disclosure provides systems and methods suitable forseparation of sulfurous materials from mixed gas streams. Moreparticularly, it has been found that carbon dioxide in its liquid formcan be highly effective as a solvent for the absorption of sulfurousmaterials from a gaseous stream. As such, liquid carbon dioxide (or afurther solvent as defined herein) can be used in some embodiments forremoving sulfurous materials from multi-component feed streams thatfurther include one or more fuel gases. This then can provide a highlycost effective means for purifying fuel gases (or other products) byremoval of substantially all of the contaminating sulfurous materialsthat may be present therein.

A multi-component feed stream suitable for treatment according to thepresent disclosure can comprise at least two components—a gaseouscomponent that is to be purified for provision as a product and asulfurous material to be separated or removed from the multi-componentfeed stream. In some embodiments, the gaseous component to be purifiedcan be a fuel gas. For example, methane or a mixture of methane andethane may be the fuel gas. In such embodiments, the multi-componentfeed stream may thus be a natural gas mixture that contains methane andsome content of higher carbon number hydrocarbons (e.g., C₂ to C₅). Insome embodiments, the fuel gas may comprise carbon monoxide and/orhydrogen. For example, the fuel gas may be syngas. As such, referenceherein to a fuel gas can mean any material that is suitable for use as afuel and that is gaseous under its normal conditions. In someembodiments, a multi-component feed stream can include any one or acombination of the following components: methane, ethane, propane,butane, pentane, hexane, carbon monoxide, and hydrogen. Preferably, themulti-component feed stream comprises at least a gaseous component andthus, the multi-component feed stream may be referred to as a gaseousmixture.

The sulfurous material to be separated or removed from themulti-component feed stream beneficially can be substantially anysulfur-containing material since the solvent utilized according to thepresent disclosure can be configured to effect removal of substantiallyall sulfur-containing species from a gaseous source. For example, liquidcarbon dioxide in particular can be effective to absorb and/or condensesubstantially all sulfur-containing species from a gaseous source. Assuch, sulfurous materials such as hydrogen sulfide (H₂S), carbonylsulfide (COS), thiol-containing materials, carbon disulfide, anddisulfide bond-containing compounds may be may be separated or removedfrom a multi-component feed stream according to embodiments of thepresent disclosure. It is understood that a thiol-containing materialcan be any organosulfur compound of the formula R-SH, wherein R is analkyl or other organic substituent. A thiol-containing material may bereferred to as a mercaptan. The sulfurous material to be removed isunderstood to be predominately in a gaseous form under removalconditions as described herein.

In an example embodiment, the present disclosure can relate to treatmentof a sour gas, which is understood to be a natural gas or any other gascontaining significant amounts of hydrogen sulfide. Sour gas may containfurther acidic gases, such as carbon dioxide gas. Although the inventionmay be discussed herein, in example embodiments, in relation totreatment of a sour gas, it is understood that the disclosure extends totreatment of any multi-component feed stream containing a sulfurousmaterial.

A multi-component feed stream suitable for treatment according to thepresent disclosure may contain at least 5 ppm, at least 10 ppm, at least50 ppm, at least 100 ppm, at least 500 ppm, at least 1,000 ppm, at least1%, or at least 2% of sulfurous materials on a molar basis. Themulti-component feed stream likewise may contain other acid gases. Insome embodiments, however, efficient removal of the sulfurous materialmay be improved when the multi-component feed stream contains a greatercontent of the sulfurous material than of other acid gases on a molarbasis. In such cases, the liquid carbon dioxide in the solvent canpreferentially remove the sulfurous material and more efficientlyprovide the purified fuel gas with substantially no sulfurous materialremaining therein.

Referring generally to FIG. 1 , a multi-component feed stream includingat least a sulfurous material and a product gas (e.g., a fuel gas) canbe processed to separate at least a portion of the sulfurous materialfrom the product gas. Specifically, the multi-component feed stream canbe injected through line 105 into a contacting column 110 from amulti-component feed stream source 102. As further described below, themulti-component feed stream may be subjected to one or more processingsteps prior to injection into the contacting column 110. For example,the multi-component feed stream may be cooled to a temperatureapproaching the freezing point of carbon dioxide. As such, themulti-component feed stream in line 105 injected into the contactingcolumn 110 may include a liquid fraction as well as a gaseous fraction.Preferably, a multi-component feed stream as described may comprise lessthan 50%, less than 40%, less than 30%, less than 20%, less than 10%, orless than 5% of a liquid fraction on a molar basis (e.g., in the rangeof about 0.1% to about 40%, about 0.1% to about 20%, or about 0.1% toabout 10% of a liquid fraction on a molar basis). As such, the termgaseous mixture may be used to define the multi-component feed streambut should not be viewed as excluding fluid streams comprising as liquidfraction as well as a gaseous fraction since two-phase flow streams canbe readily processed according to the present disclosure. For example,in some embodiments, a multi-component feed stream including a liquidfraction and a gaseous fraction may be injected directly into thecontacting column 110 using a gallery tray, chimney tray, and/or similarinternal structural components that are commonly utilized foraccommodating two-phase injection streams. As another example, amulti-component feed stream that includes a liquid fraction and agaseous fraction may be flashed prior to injection into contactingcolumn 110. In further examples, the multi-component feed streamcontaining a liquid fraction and a gaseous fraction may be separated byfraction with the gaseous fraction being injected into a middle sectionof the contacting column 110, and the liquid fraction bypassing thecontacting column 110 and being mixed with the liquid bottom streamexiting the contacting column for injection into a second column (e.g.,second contacting column 221 in FIG. 2 ).

The multi-component feed stream in line 105 preferably is contacted witha solvent within the contacting column 110. The contact between themulti-component feed stream and the solvent can be characterized as areflux or other intimate mixing, including but not limited to providingfor a counter-current flow of the multi-component feed stream againstthe solvent. As illustrated in FIG. 1 , the solvent from solvent source101 is injected through solvent line 103 into the contacting column 110.It is understood, however, that at least a portion of the solvent fromline 103 may be injected into the multi-component feed stream source 102and/or the multi-component feed stream line 105 so that removal of thesulfurous material from the multi-component feed stream may begin priorto injection into the contacting column 110. For example, themulti-component feed stream entering the contacting column 110 from line105 may comprise up to about 50%, up to about 40%, up to about 30%, upto about 20%, up to about 10%, or up to about 5% by weight of thesolvent based on the total weight of the fluid passing through line 105into the contacting column. More particularly, the multi-component feedstream entering the contacting column 110 from line 105 may compriseabout 0.1% to about 40%, about 0.2% to about 20%, about 0.5% to about15%, or about 1% to about 10% by weight of the solvent based on thetotal weight of the fluid passing through line 105 into the contactingcolumn. When solvent is included in the line 105 with themulti-component feed stream, it is understood that the solvent still maypass independently into the contacting column 110 through solvent line103.

The multi-component feed stream source 102 and/or the multi-componentfeed stream in line 105 may comprise at least some content of carbondioxide. For example, the multi-component feed stream source 102 maycomprise gaseous carbon dioxide, such as in an amount of about 0.01% toabout 20%, about 0.05% to about 10%, about 0.1% to about 5%, or about0.5% to about 3% on a molar basis. In further examples, as describedabove, liquid carbon dioxide from the solvent may be added to themulti-component feed stream prior to injecting of the multi-componentfeed stream into the contacting column. In some embodiments, prior tosaid injecting of the multi-component feed stream into the contactingcolumn, the multi-component feed stream can comprise carbon dioxide(gaseous or liquid) in an amount of at least 0.01%, at least 0.05, atleast 0.1%, at least 0.5%, at least 1%, or at least 2% on a molar basis.As otherwise described herein, the multi-component feed stream in line105 may be cooled to a substantially low temperature prior to injectinginto the contacting column 110. At such temperature, carbon dioxide inthe multi-component feed stream may be in the liquid form (either frompreviously present gaseous carbon dioxide being liquefied or from liquidcarbon dioxide from the solvent being injected into the multi-componentfeed stream stream). It is understood, however, that at least a portionof the gases originally present in the multi-component feed streamsource 102 may remain gaseous. As such, the multi-component feed streamin line 105 may be in a mixed form wherein at portion of the mixture isliquid and a portion of the mixture is gaseous. In preferredembodiments, a majority (i.e., greater than 50%) of the multi-componentfeed stream (on a molar basis) remains in a gaseous form when injectedinto the contacting column 110.

As discussed herein, liquid carbon dioxide has been found to be aparticularly useful solvent for the removal of sulfurous materials froma multi-component feed stream. It is understood that other suitablesolvents for gaseous sulfurous materials may be combined with the liquidcarbon dioxide. In example embodiments, it can be beneficial for thesolvent to comprise substantially only liquid carbon dioxide or, at aminimum to exclude other materials. For example, in some embodiments,the solvent can consist of liquid carbon dioxide or may consistessentially of liquid carbon dioxide and thus exclude any other liquidsolvent. In other embodiments, the solvent can comprise at least 60%, atleast 80%, at least 95%, at least 99%, or at least 99.9% on a molarbasis liquid carbon dioxide. In particular, it can be beneficial for thesolvent to substantially exclude any sulfurous material (i.e., meaningthat the solvent includes less than 2 ppm molar of any sulfurousmaterial). More preferably, the solvent can be completely free of anysulfurous material. The solvent particularly can be a material that isadapted to or configured to dissolve, condense, or otherwise cause thesulfurous material to separate from further components of themulti-component feed stream and exit the contacting column with a liquidstream while the remaining portions of the multi-component feed streamexits the contacting column with a gaseous stream. As such, any solventthat is adapted to or configured to cause separation of the sulfurousmaterial under operation conditions (e.g., pressure and/or temperature)as otherwise defined herein for the contacting column 110 may beutilized.

The solvent introduced to the contacting column 110 is preferably at atemperature and pressure such that substantially all of the carbondioxide that may be present in the solvent is in a liquid state.Likewise, it can be preferred for any solvent material that is utilizedto be in a liquid state when introduced into the contacting column 110.Moreover, it is preferable for the solvent to be introduced to thecontacting column 110 at a temperature and pressure so that the carbondioxide is substantially close to its freezing point while stillremaining liquid. The solvent injected into the contacting column 110thus is preferably at a temperature of about −10° C. to about −55° C.,about −25° C. to about −55° C., or about −40° C. to about −55° C. Insome embodiments, the solvent injected into the contacting column 110 isat a temperature that is within about 2° C., within about 3° C., withinabout 4° C., within about 5° C., within about 10° C., or within about20° C. of the freezing point of the solvent (or any portion of thesolvent that has the highest relative freezing point). In preferredembodiments, the solvent injected into the contacting column 110 is at atemperature that is within about 2° C., within about 3° C., within about4° C., within about 5° C., within about 10° C., or within about 20° C.of the freezing point of carbon dioxide. The contacting column 110likewise may be operated within any of the above temperature ranges.Preferably, the contacting column 110 is operated such that liquidcarbon dioxide in the solvent (or any other solvent material) does notfreeze to a solid form at any point within the contacting column. Thus,the operation of the contacting column 110 can be substantially free ofany solid carbon dioxide and/or can be substantially free of any solidsolvent component. In particular, carbon dioxide is not solidified(i.e., frozen) and then liquefied (i.e., melted) within the contactingcolumn 110. Rather, the solvent (and particularly carbon dioxide)remains liquid within the contacting column 110 so as to maximize theability to remove the sulfurous material from the multi-component feedstream. The lowest possible operating temperature without causingsolidification of the carbon dioxide (or any further solvent component)in any one or more of the solvent, the contacting column 110, and theoverhead vapor stream exiting the contacting column preferably is used.In one or more embodiments, the multi-component feed stream injectedinto the contacting column is at a temperature within one or more of theranges already described above for the solvent and the operation of thecontacting column 110. It is understood that the solvent may include afraction that is in a gaseous state when injected into the contactingcolumn 110. It is preferred, however, for a majority of the solvent tobe in a liquid state to provide for separation of the sulfurousmaterial. Thus, operating conditions of the contacting column andpre-treatment of the solvent may be such that the solvent comprises lessthan 50%, less than 25%, less than 10%, less than 5%, less than 1%, orless than 0.5% of a gaseous fraction on a molar basis (e.g., in therange of about 0.01% to about 40%, about 0.01% to about 10%, or about0.01% to about 1% of a gaseous fraction on a molar basis) when injectedinto the contacting column. As such, greater than 50%, greater than 75%,greater than 90%, greater than 95%, greater than 99%, or greater than99.5% of the solvent (on a molar basis) may be in a liquid state wheninjected into the contacting column. More particularly, the solvent maycomprise about 60% to about 99.99%, about 90% to about 99.99%, or about95% to about 99.99% of a liquid fraction on a molar basis when injectedinto the contacting column.

In some embodiments, the solvent can contain a hydrocarbon content. Asfurther described herein, at least a portion of the solvent may be arecycled stream and may include, for example, methane, such as in therange 0% to about 25% molar based on the overall concentration of thesolvent stream. Preferably, any hydrocarbon content of the solventstream will be maintained to be as low as possible. Likewise, anyhydrocarbon material present in the solvent is preferably at the lowesttemperature possible while remaining above the freezing temperature ofthe solvent. The temperature should be in practice about 2° C. to about10 ° C. above the freezing temperature and preferably about 3° C. toabout 5° C. above the freezing temperature of the solvent stream. Thesolvent preferably is provided to the contacting column 110 in asufficient concentration relative to the multi-component feed streamsuch that an overhead vapor stream in line 111 that is produced willhave a sulfurous material concentration below 2 ppm. The concentrationof sulfurous material in the overhead vapor stream in line 111 can varyas desired. For example, the overhead vapor stream in line 111 can havea concentration of sulfurous material of less than 2%, less than 1%,less than 0.1%, less than 100 ppm, less than 10 ppm, or less than 2 ppmon a molar basis. The solvent stream preferably will have the lowestpossible hydrocarbon content so as to maximize capture efficiency of thesulfurous material by the solvent, minimize the concentration ofhydrocarbons in the column overhead vapor stream in line 111, andminimize any problems that may be associated with carbon dioxide removaldownstream. Optionally the contacting column 110 may be equipped with anoverhead condenser and a reboiler if desired to mitigate such issues.Various implementations of condensers and reboilers are described inrelation to the appended Example, and it is understood that any one orany combination of contacting columns (e.g., distillation columns)described herein may be equipped with one or both of a condenser and areboiler.

The solvent and/or the multi-component feed stream may be subjected toone or more treatments prior to injection into the contacting column 110to achieve one or more desired physical conditions for the respectivestreams. For example, one or both of the solvent and the multi-componentfeed stream may be cooled to the desired temperature range. Asillustrated in FIG. 1 , the solvent leaving the solvent source 101 andthe multi-component feed stream leaving the multi-component feed streamsource 102 are already at the desired temperature. If cooling is to beapplied, however, any refrigeration or other heat exchange suitable tocool one or both streams to the desired temperature range (e.g., to atemperature close to about −56° C.) may be used. Example embodiments ofcooling units suitable according to the present disclosure are morespecifically described in relation to Example 1. In particular, a heatexchange system used for cooling one or both of the solvent and themulti-component feed stream may also be utilized to heat the overheadvapor stream in line 111 and/or one or more further gas stream asotherwise discussed herein to a greater temperature, such as to nearambient temperature. When a heat exchanger is used (see heat exchanger 7in the appended Example), any deficiency of refrigeration can beprovided by a suitable system, such as a closed cycle refrigeration loop(see refrigeration unit 8 in Example 1) with a working fluid capable ofproviding refrigeration at the required low temperature level.Optionally the refrigeration loop can provide refrigeration at two ormore temperature levels. Optionally the refrigeration can be provided bya refrigerant fluid comprised of pure carbon dioxide or carbon dioxidemixed with other gases (e.g., methane) evaporating at a temperaturelevel close to its freezing temperature. If desired, any refrigerationmeans known in the art may be utilized. For example, suitablecombinations of expansion and recompression may be carried out toprovide cooling, and this can encompasses systems and methods designedto utilize the Joule-Thomson Effect.

More particularly, prior to injecting the multi-component feed stream inline 105 and/or the solvent in line 103 into the contacting column 110,one or both of these streams may be passed through a heat exchangeragainst at least a portion of an overhead vapor stream 111 that iswithdrawn from the contacting column 110 so that the overhead vaporstream is heated and one or both of the multi-component feed stream andthe solvent stream is cooled. In one or more embodiments, refrigerationfor one or both of the multi-component feed stream in line 105 and thesolvent in line 103 can be provided with a refrigeration system (e.g., aclosed cycle loop) using a suitable refrigerant. In this manner, one ormore streams of the liquid refrigerant can be evaporated in the heatexchanger (e.g., at the same or at different temperature levels) tomaintain a heat balance thereof. In some embodiments, the liquidrefrigerant can comprise liquid carbon dioxide.

Preferably, the carbon dioxide that utilized in the liquid solvent inline 103 can be provided at a pressure and a temperature so that thecarbon dioxide is at a desired density range. For example, the carbondioxide can have a density of about 0.6 Kg/L or greater, about 0.7 Kg/Lor greater, or about 0.75 Kg/L or greater. To this end, carbon dioxidethat is passed through a heat exchanger to be cooled prior to entry intothe contacting column 110 may be at a pressure that is substantiallyclose to or above the critical pressure of carbon dioxide and that issubstantially close to ambient temperature. More particularly, thecarbon dioxide can have a pressure in the range of about 50 bar to about85 bar or about 65 bar to 75 bar. The pressure of the solvent stream canbe reduced to the column pressure in a suitable valve following coolingin the heat exchanger (see the valve 31 in FIG. 4 ). Alternatively, thesolvent stream can be provided at a pressure slightly higher than theoperating pressure of the contacting column 110 and be cooled to thedesired temperature near its freezing point in a refrigeration heatexchanger.

In one or more embodiments, the multi-component feed stream may bepre-treated to separate any liquid phase water and optionallyhydrocarbons above C₄. The so treated multi-component feed stream maythen be dried to a dew-point that is below the operating temperature ofthe contacting column 110, preferably below a dew point of about −56° C.or below a dew point of about −60° C. Such drying may be carried out,for example, in a thermally regenerated desiccant drier. The solventstream likewise can be provided with a dew-point in one or more of theabove-noted ranges. The dried crude multi-component feed stream and thedried solvent stream are then cooled in the heat exchanger to the lowtemperature required for operation of the contacting column 110. As seenin FIG. 1 , the solvent leaving the solvent source 101 and themulti-component feed stream leaving the multi-component feed streamsource 102 may already have the desired dew-point. Alternatively,referring to the appended Example, the present system and method mayinclude carrying out the desired drying in order to achieve the desireddew-point.

In some embodiments, further or alternative components may be utilizedfor providing one or both of the solvent in line 103 and themulti-component feed stream in line 105 to the contacting column 110 atthe appropriate temperature and/or pressure range. For example, themulti-component feed stream from multi-component feed stream source 102may be compressed (e.g., to a pressure of at least 60 bar) in anintercooled multi-stage compressor prior to being dried in a drying bed(e.g., a bed packed with appropriate desiccant material, such asmolecular sieves or zeolites), preferably to a dew point ofsubstantially close to −60° C. The dried stream may then be reduced inpressure by passage through a first valve before passage through a heatexchanger. Finally, the stream may be further expanded in a secondexpansion valve to form a stream at a temperature near the carbondioxide triple point temperature of about −56.4° C. This stream (i.e.,either or both of the solvent stream and the multi-component feedstream) can then be fed to a contacting column as otherwise describedherein. The cool overhead vapor from the contacting column 110 can beutilized as a source of refrigeration for one or more further streams,such as in the main heat exchanger used in the system as described (seeheat exchanger 7 in the appended Example).

The contacting column 110 can be any structure that allows for injectionof the necessary streams and provide for contacting therein of theinjected streams. For example, the contacting column 110, in someembodiments, may be a distillation column and thus may include anynumber of plates as may be present in a typical fractionatingdistillation column. Alternatively, the contacting column 110 maycontain any suitable packing material that typically may be utilized infractionating columns. The contacting column 110 may be characterized asa counter-current contacting column wherein an injected gaseous streampasses upward for contacting an injected liquid stream that passesdownward. The contacting column 110 preferably may be adapted to orconfigured to effectively handle a two-phase feed stream. For example,the contacting column 110 may be adapted to or configured to provide forany one or more of the following: flash a feed stream in a flash vesselprior to the entrance to the column; use a gallery tray or chimney tray;include heating elements such as heating coils or tubing containingheating fluids such as steam or other process streams in internalsections of the column in order to adjust the boil-up within the columnand obtain desired separation performance over its top and bottomproducts.

The operating pressure of the contacting column 110 preferably is belowthe critical pressure of the fluids in the contacting column at allpoints. In example embodiments, the contacting column can operate at apressure in the range of about 7 bar to about 100 bar, about 10 bar toabout 70 bar, about 7 bar to about 60 bar, about 30 bar to about 50 bar,or about 20 bar to about 50 bar. Likewise, the solvent stream and/or themulti-component feed stream may be injected to the contacting column 110at a pressure within one or more of the ranges noted above.

In practice, the multi-component feed stream from line 105 contactsliquid carbon dioxide from the solvent in line 103 within the contactingcolumn 110 to achieve the desired removal of the sulfurous material fromthe mixed gas stream. As noted above, a portion of the solvent streammay be combined with the multi-component feed stream prior to injectioninto the contacting column 110; however, it is understood that at leasta portion of the transfer of the sulfurous material from themulti-component feed stream to the solvent is carried out within thecontacting column 110. In particular, the sulfurous material istransferred from the multi-component feed stream to the liquid carbondioxide within the contacting column, and two separate streams may bewithdrawn therefrom. A bottom product stream 116 can be withdrawn from alower portion of the contacting column 110, the bottom product streamcontaining at least a portion of the sulfurous material from themulti-component feed stream, and an overhead vapor stream in line 111can be withdrawn from an upper portion of the contacting column, theoverhead vapor stream containing at least a portion of the product gasfrom the multi-component feed stream. In one or more embodiments, thebottom product stream 116 can include substantially all of the sulfurousmaterial from the multi-component feed stream. In embodiments whereinthe multi-component feed stream is a natural gas, the bottom productstream 116 may likewise include substantially all of the C₃ or higherhydrocarbons that are present as well as a minor amount of gaseouscarbon dioxide and methane and/or ethane.

In one or more embodiments, a re-boiler (e.g., a heat exchanger) may beutilized at the base of the contacting column 110 to ensure that thebottom product stream 116 from the contacting column containssubstantially all of the sulfurous material from the multi-componentfeed stream. In the case where the multi-component feed stream includesa natural gas, the use of the re-boiler can further ensure that theproduct stream 116 contains substantially all of the higher hydrocarbons(e.g., C₃ to C₅ or greater) present in the multi-component feed stream.An example embodiment of a re-boiler is described in Example 1. The useof the reboiler can also be useful to ensure that the overhead vaporstream in line 111 from the contacting column 110 contains a majority ofthe gaseous carbon dioxide from the multi-component feed stream and, incases where the multi-component feed stream is a natural gas, to ensurethat the overhead vapor stream contains a majority of the methane andethane present from the multi-component feed stream. The re-boiler maybe separate component from the contacting column 110 or may beintegrally formed with the contacting column. The heating stream for there-boiler can come from any suitable source. In some embodiments, atleast a portion of the multi-component feed stream is passed through there-boiler prior to injecting into the contacting column 110. In thismanner, the multi-component feed stream can provide heating to there-boiler while being cooled prior to entry into the contacting column110.

In embodiments wherein the multi-component feed stream is a natural gas,the overhead vapor stream in line 111 preferably comprises substantiallyno hydrocarbons greater than C₂. For example, the overhead vapor streamin line 111 exiting the contacting column 110 preferably includes lessthan 1%, less than 0.1%, less than 100 ppm, less than 10 ppm, or lessthan 5 ppm of C₃, C₄, or C₅, on a molar basis, each individually or intotal.

The overhead vapor stream in line 111 exiting the contacting column 110may be passed through one or more units for further treatment. Anoverhead vapor treatment unit 121 is shown in FIG. 1 and may include oneor more treatment sections. In some embodiments, it can be useful tofirst heat the vapor stream, such as to near ambient temperature. Thiscan be done utilizing dedicated heating (e.g., as a component of theoverhead vapor treatment unit 121) or utilizing heat available fromanother unit. For example, the overhead vapor stream in line 111 may bepassed through the heat exchanger that is utilized for cooling of one orboth of the solvent stream and the multi-component feed stream. Thisutilizes heat withdrawn from one or both of the original solvent streamand the original mixed gas stream in order to heat the overhead vaporstream.

The overhead vapor stream in line 111 may be subjected to one or moreseparation steps in order to separate the vapor stream into desiredconstituents. The overhead vapor treatment unit 121 thus may include oneor more separation units. For example, when the mixed gas stream 105 isa natural gas stream, the overhead vapor stream in line 111 may compriseat least methane and gaseous carbon dioxide. Accordingly, it can bebeneficial to separate at least a majority of the gaseous carbon dioxidefrom the methane to provide a high purity methane stream. Such conceptcan be applied equally to any overhead gas stream to the extent that itincludes multiple components. The concentration of sulfurous material inthe product gas stream in line 125 can vary as desired based upon theefficiency of the removal of sulfurous material in the contacting column110. For example, the product gas stream (e.g., a fuel gas) in line 125can have a concentration of sulfurous material of less than 2%, lessthan 1%, less than 0.1%, less than 100 ppm, less than 10 ppm, or lessthan 2 ppm on a molar basis. This low concentration of the sulfurousmaterial can be particularly beneficial since the product can, in one ormore embodiments, be a fuel gas, and at least a portion of such fuel gascan be provided into a combustor of a power production unit.

In one or more embodiments, the overhead vapor treatment unit 121through which the overhead vapor stream in line 111 can be passed cancomprise a single stage or multi-stage (e.g., two stage) membrane gasseparator. Any suitable membrane gas separator may be utilized such as,for example, a UOP Separex™ Membrane System that is particularlydesigned for separation of acid gases and water from natural gas. In anexample wherein the overhead vapor stream in line 111 is derived from asour natural gas as the multi-component feed stream source 102, the usea membrane separator can be effective to separate the bulk of thegaseous carbon dioxide from the product natural gas stream (which ispredominately methane) which leaves the membrane system as thenon-permeate high pressure stream. This is further described in relationto Example 1. The thus purified product gas stream preferably has acarbon dioxide content that is within a desirably low range, such asless than 5%, less than 4%, less than 3%, or less than 2% carbon dioxidecontent on a molar basis. The presence of methane and ethane in thegaseous carbon dioxide stream exiting the membrane separator can beminimized by using a two stage membrane unit. The number of membraneseparators utilize can be chosen based upon the carbon dioxide contentof the original multi-component feed stream source 102. Furtherreductions in the methane content of the separated gaseous carbondioxide can depend on the economics of recovering more purified naturalgas. In one embodiment, for example, the permeate stream from a singlestage membrane unit may be compressed to a pressure that is greater thanthe operating pressure of the contacting column and then cooled in theheat exchange system to a temperature in the range that is slightlyabove the freezing temperature of carbon dioxide (e.g., about 2° C. toabout 10° C. or about 3° C. to about 5° C. above the freezingtemperature of carbon dioxide). The gas stream may then be fed to asecond distillation column which has a reboiler and optionally anoverhead condenser. The function of this column can be to separatemethane from carbon dioxide in a section of stages below the feed pointto produce a purified carbon dioxide liquid bottom product streamcontaining less than 10% methane and typically about 1% to 6% methane,which provides both the net carbon dioxide product stream and, followingcooling, the liquid carbon dioxide reflux to the contacting column.

As illustrated in FIG. 1 , the overhead vapor stream in line 111 can betreated in the overhead vapor stream treatment unit 121 to provide atleast a carbon dioxide permeate stream 123 and a gas product stream 125.Since the carbon dioxide permeate stream 123 preferably contains lessthan 2 ppm of the sulfurous material, the carbon dioxide permeate streamcan be recycled to supply at least a portion of the carbon dioxide inthe solvent stream. As such, the carbon dioxide permeate stream 123 canprovide one or more of a carbon dioxide product 124, a carbon dioxidefeed 126 to the solvent source 101, a carbon dioxide feed 127 to themulti-component feed stream line 105, and a carbon dioxide make-up feed128 to the solvent line 103. Preferably, the carbon dioxide can becompressed and cooled to near ambient temperature before being combinedwith the solvent. In further embodiments, at least a portion of thecompressed carbon dioxide permeate stream in line 123 can be cooledsubstantially closed to its freezing point, such as through passagethrough a heat exchanger as further described herein (see, for example,heat exchanger 7 in the appended Example). The carbon dioxide permeatestream can be cooled, for example to a temperature of about −20° C. toabout −55° C., about −30° C. to about −55° C., or about −40° C. to about−55° C. The cooled carbon dioxide permeate can then be injected into adistillation column (see column 50 in the appended Example), and aliquid bottom product that is enriched in carbon dioxide (e.g., at least80%, at least 85%, at least 90%, or at least 95% pure on a mole basis)can be withdrawn from the distillation column. With reference to FIG. 1, the withdrawn liquid carbon dioxide stream can be the stream providedin one or both of lines 126 and 128, and this liquid carbon dioxidestream can account for a majority of the solvent provided in line 103 tothe contacting column 110.

Beneficially, in one or more embodiments, the present systems andmethods can operate with internal recycle of carbon dioxide atsubstantially low concentrations of carbon dioxide in themulti-component feed stream since substantially the only consumption ofcarbon dioxide in the process is the content of carbon dioxide thatremains in the product gas stream exiting the membrane separator. Anynet carbon dioxide product 124 produced from excess carbon dioxide inthe multi-component feed stream can be removed for disposal. Suchproduced carbon dioxide can be used for a variety of end purposes, suchas a fluid for enhanced oil recovery, or sequestered in a geologicformation. In some embodiments, the net carbon dioxide may be used as atleast part of the fuel feed stream to a CO₂ power production cycle wherethe methane content would contribute to the fuel requirement. The carbondioxide derived from both the excess carbon dioxide and the carbon inthe methane fraction would be delivered at 100% recovery and all theheat of combustion of the minor methane content would be utilized. Otheralternative options to control the carbon dioxide content of the gaseousproduct stream may include an absorption-based system such as amineprocess or other types of carbon dioxide removal apparatus solely or inany combination with first and second option explained above. Forexample, a one-stage membrane followed by an amine process may beimplemented. A downstream amine absorber may be particularly useful whena purified natural gas product stream is expected to be furtherrefrigerated in an LNG plant and carbon dioxide content of 50 ppm orless is desired.

The bottom product stream in line 116 may be further processed asdesired to separate the stream into one or more of its constituents, andsuch treatment can vary depending upon the composition of the originalmulti-component feed stream that is introduced to the contacting column110. As illustrated in FIG. 1 , the bottom product stream in line 116may be further processed in the bottom product separation unit 131,which may comprise a plurality of separate components. In particularembodiments, the bottom product stream in line 116 may be passed throughone or more further contacting columns (e.g., distillation columns) tosequentially separate the stream into individual fractions that eachpredominately comprises a desired component of the bottom productstream. Separation(s) carried out using the bottom product separationunit 131 can result in the formation of at least two exiting streams.Specifically, stream 132 can comprise at least carbon dioxide, andstream 133 can comprise at least sulfurous material.

In some embodiments, the bottom product separation unit 131 can beadapted to or configured to carry out a Claus process wherein sulfurcompounds can be converted into elementary sulfur. In some embodiments,the bottom product separation unit 131 can be adapted to or configuredto carry out process steps wherein sulfur compounds are converted intoconcentrated sulfuric acid. In some embodiments, the bottom productseparation unit 131 can be adapted to or configured to carry out sulfurcombustion with flue gas desulfurization wherein sulfur compounds areconverted into gypsum. In some embodiments, the bottom productseparation unit 131 can be adapted to or configured to carry out mineralcarbonation storage wherein the carbon dioxide and hydrogen sulfide maybe mixed with further compounds.

The separation(s) carried out using the bottom product separation unit131 can be illustrated using an example wherein the originalmulti-component feed stream source 102 is a sour natural gas streamcomprising at least methane, C₂ and greater hydrocarbons, gaseous carbondioxide, and hydrogen sulfide. In such example, the separation sequencecan be designed to provide a hydrogen sulfide stream that preferablycontains less than 1% CO₂ content and also provide a hydrocarbon stream(e.g., containing C₃ or greater hydrocarbons), preferably with less than2 ppm hydrogen sulfide content. This example is further discussed belowwith reference to FIG. 2 and FIG. 3 .

Referring to FIG. 2 , sour natural gas can be injected through line 205into a first contacting column 210 from a sour natural gas source 202,and a liquid carbon dioxide containing solvent from solvent source 201is injected through line 203 into the first contacting column. The firstcontacting column 210 can be characterized as a de-methanizer contactingcolumn as the overhead vapor stream in line 211 exiting the firstcontacting column can comprise predominately methane (i.e., can containa majority of methane present in the sour natural gas). In the system ofFIG. 2 , the overhead vapor stream treatment unit 221 can be a singlestage membrane separator or a multi-stage membrane separator configuredto provide a non-permeate stream exiting in line 225. The non-permeatesteam derived from the sour natural gas can comprise substantiallycompletely methane with a minor content of gaseous carbon dioxide andpreferably substantially no hydrogen sulfide (e.g., less than 2 ppmhydrogen sulfide on a molar basis). The non-permeate, product gas streamin line 225 preferably has a gaseous carbon dioxide content of about 5%or less, about 4% or less, about 3% or less, or about 2% or less on amolar basis. The overhead vapor stream treatment unit 221 further can beconfigured to provide a permeate stream in line 223 that is formedpredominately or substantially completely of carbon dioxide andpreferably contains less than 2 ppm of the hydrogen sulfide. At least aportion of the, the carbon dioxide permeate stream in line 223 iswithdrawn from the system as a carbon dioxide product stream in line224. Optionally, a portion of the carbon dioxide permeate stream can berecycled to the solvent line 203 in carbon dioxide make-up feed line228.

The bottom product stream in line 216 is further processed in a bottomproduct separation unit that comprises a plurality of components. Thebottom product stream in line 216 can comprise at least a portion of anyhydrogen sulfide and C₁ to C₅ hydrocarbons present in the sour naturalgas. In some embodiments, the bottom product stream in line 216 cancontain substantially all of any C₃ or greater hydrocarbons,substantially all of the hydrogen sulfide originally present in thenatural gas, and varying amounts of C₂ (ethane) and carbon dioxide. Inthe illustrated embodiment, the bottom product stream in line 216 isfirst passed to a second contacting column 231 that can be configured toseparate a majority or substantially all of the ethane that is presentin the bottom product stream. The second contacting column, for examplecan be configured to include a reboiler and an overhead condenser toprovide for re-boil and reflux within the second contacting column.Thus, the second contacting column may be characterized as being ade-ethanizer unit. As such, an ethane stream may exit the secondcontacting column 231 in line 232, and the ethane stream can comprise amajority of any carbon dioxide that did not leave the first contactingcolumn 210 in the overhead vapor stream in line 211. More particularly,separation in the second contacting column 231 can be adapted to orconfigured to produce an overhead carbon dioxide rich vapor streamcontaining preferably less than 2 ppm hydrogen sulfide (on a molarbasis), preferably less than 100 ppm C₃ or greater hydrocarbons (on amolar basis), and preferably greater than 50% molar of any ethaneoriginally present in the sour natural gas source. The C₂/CO₂ streamleaving the second contacting column 231 in line 232 can be optionallyfurther compressed and then combined with the overhead vapor stream inline 211 or injected directly into the overhead vapor stream treatmentunit 221.

Depending on the composition of the sour natural gas source and theparticular design of the first contacting column 210, the bottom productstream in line 216 can include some content of methane. For example, thebottom product stream in various embodiments can comprise 50% or less,40% or less, 30% or less, 20% or less, 10% or less, 5% or less, or 1% orless methane on a molar basis. In some embodiments, the methane contentof the bottom product stream in line 216 can be about 500 ppm or less,about 100 ppm or less, about 10 ppm or less, or less than 1 ppm on amolar basis. Several azeotrope mixtures may be formed in the secondcontacting column 231 such as C₂/CO₂, C₂/H₂S, and C3/H₂S. Since it ishighly desirable to separate a maximum quantity of the ethane into thetop product stream exiting the second column in line 232, therepreferably is a sufficient methane content in the column bottoms toensure that the second contacting column 231 produces at least 75% andpreferably greater than 90% of the ethane in the sour gas source 202 inthe top product stream by adjusting the methane content of the streamentering the second contacting column in line 216. Optionally the firstcontacting column 210 can be adapted to or configured to provide amethane concentration in the bottom product stream of less than 5%molar, and a stream of liquid carbon dioxide can be added to the bottomproduct stream in line 216 to give a high recovery of ethane in thesecond contacting column overhead stream in line 232. Moreover, thesecond contacting column 231 can be adapted to or configured to providethe overhead vapor stream in line 232 with substantially no C₃ and/or C₄hydrocarbons—i.e., about 500 ppm or less, about 200 ppm or less, about100 ppm or less on a molar basis.

In some embodiments, the second contacting column 231 can be adapted toor configured to enhance ethane recovery in the overhead stream in line232. For example, the second contacting column 231 can include one ormore inputs for receiving a stream comprising C₄ hydrocarbons andoptionally C₃ and/or C₅ or greater hydrocarbons. In some embodiments,the additive stream can comprise predominately C₄ or greaterhydrocarbons and may comprise less than 5% or less than 2% (on a molarbasis) of any C₃ hydrocarbons. As illustrated in FIG. 2 , thehydrocarbon stream may be provided from an external source in line 258and/or may be a recycle stream in line 257 a taken from a furthercomponent of the system (such as described below). The addition of thehigher hydrocarbon stream to second contacting column 231 can be usefulto improve the separation of carbon dioxide and ethane from thesulfurous material and the C₃ and higher hydrocarbons mixture that ispresent in the liquid bottom stream in line 216. As a result, theoverhead vapor stream in line 232 can be enriched in ethane and carbondioxide and can include substantially no hydrogen sulfide (e.g., lessthan 2 ppm on a molar basis). Likewise, the liquid bottom stream in line233 can be provided with substantially all of the hydrogen sulfide andthe C₃ and greater hydrocarbons within the feed stream.

In one or more embodiments, a content of carbon dioxide may be added tothe bottom product stream in line 216 exiting the first contactingcolumn 210. Such addition can be suitable so that the combined carbondioxide plus methane content of the bottom product stream in line 216 issufficient to ensure that greater than 75% and preferably greater than90% of any ethane present in the bottom product stream can be separatedas part of an overhead vapor stream from the second distillation column231, which can include a reboiler and/or an overhead condenser. Inparticular, the carbon dioxide content in the bottom product stream inline 216 may be adjusted as desired to be in the range of about 2% toabout 50%, about 5% to about 45%, about 10% to about 40%, or about 20%to about 40% on a molar basis.

A liquid bottom product exits the second contacting column 231 in line233 and is fed into a third contacting column 241, which can include areboiler and/or an overhead condenser. The liquid bottom product in line233 exiting the second contacting column 231 preferably includessubstantially no methane—i.e., about 500 ppm or less, about 100 ppm orless, about 10 ppm or less, or less than 1 ppm on a molar basis. In someembodiments, the stream in line 233 can be at a pressure of about 5 barto about 50 bar, about 7 bar to about 30 bar, or about 10 bar to about20 bar. An overhead vapor stream exiting the third contacting column 241in line 242 can comprise substantially all (e.g., at least 98%, at least99%, at least 99.5%, or at least 99.9% on a molar basis) of the hydrogensulfide from the original sour natural gas source 202. Removal of thehydrogen sulfide in the third contacting column 241 can include addingto the column a reflux stream comprising C₄ and greater hydrocarbons,which can be provided from an external source or optionally can be takenfrom an exit stream of a further component of the system (such asdescribed below). The addition of the higher hydrocarbon stream to thethird contacting column 241 allows substantially all of the C₃ andgreater hydrocarbons from the sour natural gas source 202 to bedelivered as a liquid bottom stream in line 243 that includessubstantially no hydrogen sulfide (e.g., less than 2 ppm on a molarbasis). In some embodiments, the overhead vapor stream in line 242 canbe enriched in carbon dioxide—e.g., comprising about 0.1% to about 20%,about 0.5% to about 15%, or about 1% to about 10% carbon dioxide on amolar basis. The bottom product in line 243 exiting the third contactingcolumn can be provided into a separation unit 251, which can functionsubstantially as a de-propanizer and which can include a reboiler and/oran overhead condenser, and which can comprise, for example, aconventional natural gas liquids separation system. Processing in theseparation can be effective to separate the liquid bottoms stream inline 243 into the various product streams, such as propane, butane, andlight C₅ and greater hydrocarbons (e.g., naphtha). A propane stream canbe withdrawn in line 252, and the C₄ and greater hydrocarbon stream canbe withdrawn in line 253. As illustrated, all or a portion of thenaphtha stream (or other mixture of C₄ and greater hydrocarbons) can betaken as a product stream in line 255. If desired, a portion of the C₄and greater hydrocarbon stream in line 253 can be separated into line257 as a recycle stream to provide part or all of a reflux stream—e.g.,provided in line 257 a into the third contacting column 241 and/orprovided in line 257 b into the second contacting column. The presentlydisclosed system thus can provide for highly efficient separation ofhydrogen sulfide, carbon dioxide, and light hydrocarbon streams (e.g.,liquefied petroleum gas (LPG), which can comprise mainly propane, mainlybutane, or a mixture thereof) from a sour natural gas feed stream withlow capital cost, low utility consumption (and thus low operating cost),and zero emission of carbon dioxide to the atmosphere.

In one or more embodiments, it may be desirable to provide an ethaneproduct stream separate from the non-permeate stream exiting in line 225that comprises mainly methane when starting with a sour natural gassource 202. The system and method may be implemented substantially asalready described above. With reference to FIG. 3 , however, theoverhead vapor stream leaving the second contacting column 231 in line232 (which comprises ethane and carbon dioxide) can be processed toseparate a substantially pure ethane stream from the ethane and carbondioxide. This may be accomplished, for example, by passing the overheadvapor stream in line 232 to a carbon dioxide separation unit 261 whereinthe stream of ethane and carbon dioxide is heated to near ambienttemperature, and at least 50%, at least 75%, or at least 90% of thecarbon dioxide on a molar basis present in the stream in line 232 isseparated out. A stream of substantially pure carbon dioxide may thenexit the carbon dioxide separation unit 261 in line 262, and a stream ofethane and higher hydrocarbons may be passed in line 263 to an ethaneseparator 271, which can include a reboiler and/or an overheadcondenser, and which can comprise any conventional ethane separationsystem. The ethane separator can be effective to provide an ethanestream (which is preferably substantially pure) in line 272 and a streamof C₄ and greater hydrocarbons in line 273, which stream can be mixedwith the product stream in line 255 comprising mainly C₄ and greaterhydrocarbons. This can be particularly useful in embodiments wherein theamount of ethane in the sour natural gas source is relatively high. Insome embodiments, the separation unit 261 may be a membrane separationunit. Moreover, the separation unit 261 can be adapted to or configuredto remove at least 80%, at least 85%, or at least 90% of any carbondioxide present in the overhead vapor stream in line 232 exiting thesecond distillation column 231.

Another alternative configuration to enhance ethane recovery in thesecond contacting column 231 and potentially produce a high purityethane product stream can comprise introducing an additive stream to anappropriate location proximate the top of the second contacting column231 to break azeotropes within the column. As described above, this canprovide for maximizing the recovery of ethane and carbon dioxide in theoverhead vapor stream leaving the second contacting column 231 in line232. The additive stream additionally or alternatively may be added tothe third contacting column 241. The additive stream is preferably ahydrocarbon stream rich in C₄ hydrocarbons but also can contain C₃and/or C₅ or greater hydrocarbons. In some embodiments, the additivestream can comprise predominately C₄ or greater hydrocarbons and maycomprise less than 5% or less than 2% (on a molar basis) of any C₃hydrocarbons. The overhead vapor stream leaving the second contactingcolumn in line 232 thus can be either mixed with the overhead vaporstream leaving the first contacting column 210 in line 211 prior to thecarbon dioxide separation or can be further processed to separate ethaneand carbon dioxide and also recover an additive stream. The latter canbe accomplished when the separation unit 261 is a carbon dioxiderecovery column, and the overhead vapor stream leaving the secondcontacting column in line 232 is directed to the carbon dioxide recoverycolumn equipped with a reboiler and condenser wherein a carbon dioxiderich stream can be withdrawn from a top portion of the column in line262. The liquid bottom product from the carbon dioxide recovery columnin line 263 can be introduced into the ethane separator 271 (e.g., anethane recovery column), equipped with a reboiler and condenser, whereinan overhead vapor stream enriched in ethane is provided in line 272, andliquid bottom mainly containing additive stream component is provided inline 273. A portion of the C₄ and greater hydrocarbon stream in line 257may be provided in line 257 c to the separation unit 261. A furthercarbon dioxide separation unit 281 may be provided for receiving thepermeate stream in line 223 that comprises mainly carbon dioxide. Thisseparation unit 281 can be adapted to or configured to provide a vaporstream in line 223 a (which can comprise mainly methane and a variablecontent of carbon dioxide and/or ethane) that can be mixed with thestream in line 211 prior to input to the overhead vapor stream treatmentunit 221. The separation unit 281 further can be adapted to orconfigured to provide a stream of liquid carbon dioxide in line 223 b.Such liquid carbon dioxide can be substantially pure in someembodiments. As desired, the liquid carbon dioxide in line 223 b can beutilized as a solvent and added through line 228 to stream 203 and/ormay be exported in line 224.

The systems and methods described herein can be integrated with anychemical process that requires clean-up of a gaseous stream includingsulfur species, and hydrogen sulfide in particular. Any carbon dioxideutilized in the solvent may be derived from a number of sources and, forexample, can originate from a carbon dioxide containing stream withinthe integrated process or an external source.

In some embodiments, the systems and methods described herein can beintegrated with an oxy-fuel power cycle where in the fuel gas stream iscontaminated with sulfur species, such as hydrogen sulfide. The inherentnature of oxy-fuel combustion enables facile separation of by-productcarbon dioxide from fuel combustion. This carbon dioxide by-product canbe used to clean-up the fuel gas feed if it is contaminated with sulfurspecies. Any one or more of the streams described herein comprising afuel gas may be utilized in an oxy-fuel combustion system. Asnon-limiting examples, any of the following streams may be utilized asthe fuel stream: the overhead vapor stream leaving the first contactingcolumn (110, 210) in line 111/211; the permeate stream exiting a singlestage membrane separation unit (121, 221) in line 123/223; the vaporstream exiting the separation unit 281 in line 223 a.

In one or more embodiments, it may be desirable to provide a productstream that has a very low carbon dioxide content. As such, it can bebeneficial to treat the overhead vapor stream (111, 211) utilizing oneor more further contacting columns. For example, referring to FIG. 1through FIG. 3 , the overhead vapor stream treatment unit (121, 221)into which the overhead vapor stream (111, 211) is injected can be adistillation column. More particularly, the overhead vapor stream (111,211) can be injected into a substantially middle section of thedistillation column forming the overhead vapor stream treatment unit(121, 221), and a stream of C₄ and greater hydrocarbons can beintroduced into the distillation column above the injection point of theoverhead vapor stream. At least a portion of the stream of C₄ andgreater hydrocarbons can be a stream taken from line 257 (or a branchthereof). If beneficial, at least a portion of the stream of C₄ andgreater hydrocarbons can be provided from an outside source. Theintroduction of the C₄ and greater hydrocarbons into the distillationcolumn can be useful to substantially suppress the freezing of carbondioxide present in the overhead vapor stream (111, 211) which wouldotherwise be expected to occur at typical temperatures required toobtain methane purity of greater than 90% molar. For example, at apressure of about 40 bar, the required condenser temperature to obtainmethane with approximately 50 ppm molar carbon dioxide content is about−88° C. The amount of the C₄ and greater hydrocarbons that is injectedinto the distillation column can be chosen such that freezing of carbondioxide will be substantially or completely suppressed at all pointswithin the distillation column and any associated condenser. Accordingto such embodiments, the bottom liquid product can exit the distillationcolumn in line 123/223 and can mainly contain carbon dioxide andsubstantially all of the C₄ and greater hydrocarbons introduced into thecolumn. The bottom liquid product can be optionally reduced in pressureand processed in a further carbon dioxide separation unit (see 281 inFIG. 3 ), which may be a flash column or a second distillation column.This additional processing can provide high purity carbon dioxide as anoverhead product (e.g., as in line 223 b of FIG. 3 ) and recover the C₄and greater hydrocarbons as the bottom liquid product stream. The C₄ andgreater hydrocarbons that are recovered from the carbon dioxideseparation unit can be pumped and recycled back into the system. Carbondioxide can be optionally recompressed and reused as the solvent for thecontacting column (110, 210) and/or exported. The product stream in line125/225 thus can comprise a product gas (e.g., methane) withsignificantly low content of sulfurous material (e.g., less than 2 ppmmolar) and a tunable carbon dioxide content that can be similarly low(e.g., less than 500 ppm, less than 100 ppm, or less than 10 ppm) asdesired.

In further embodiments, the present systems and methods can provide forthe expansion of existing natural gas processing plants wherein anexisting carbon dioxide removal system generates a stream of pure carbondioxide by-product. The methods described here can take the advantage ofan available CO₂ stream and increase the sulfur-removal capacity of theplant.

In other embodiments, the present systems and methods can be utilized inremoving sulfur from syngas produced from coal gasification process, andthe cleaned syngas can be used for power generation or chemicalproduction, such as with an integrated gasification combined cycle(IGCC) or a Poly-Gen process. Typically, clean and pure carbon dioxidecan be produced from an IGCC system with pre-combustion carbon dioxideremoval or from a chemical production system. Carbon dioxide can be usedas for the removal of H₂S/COS and other reducing sulfur species in theraw syngas produced from a coal gasification process.

The presently disclosed systems and methods can be utilized generally toprocess a contaminated multi-component feed stream (e.g., contaminatedwith a sulfurous material) to provide a cleaned product gas and a streamcomprising at least the contaminant. The latter stream can be processedin a variety of manners to provide further products. Non-limitingexamples of the further processing are provided below.

In one or more embodiments, the present disclosure can encompass systemsand methods wherein a multi-component feed stream including a sulfurousmaterial is injected in line 505 into a sulfur separation system 500that may include any combination of parts as otherwise described hereinto provide for separation of at least a portion of the sulfurousmaterial from the multi-component feed stream. A substantially purifiedgaseous product is thus provided in line 525, and sulfurous product isprovided in line 542 to a sulfur process unit 590. Processing in thesulfur process unit can be carried out in a variety of manners and canbe adapted to or configured to provide a stream of substantiallypurified sulfur product in line 591, a solvent export stream in line592, and a solvent recycle stream in line 593.

In one or more embodiments, the present disclosure can encompassessystems and methods wherein a multi-component feed stream including asulfurous material is contacted with a solvent comprising liquid carbondioxide, and one or more processing steps from an oxy-Claus process arecarried out in order to provide a substantially clean product gas,elemental sulfur, and carbon dioxide. In such embodiments, amulti-component feed stream including a sulfurous material can beprocessed as already described herein such that the sulfurous materialfrom the multi-component feed stream is separated by the liquid carbondioxide and removed as a liquid bottom product and a gaseous productthat is substantially free of the sulfurous material is removed as anoverhead vapor stream. As shown in FIG. 6 , a multi-component feedstream including a sulfurous material is injected in line 605 into asulfur separation system 600 that may include any combination of partsas otherwise described herein to provide for separation of at least aportion of the sulfurous material from the multi-component feed stream.A substantially purified gaseous product is thus provided in line 625,and sulfurous product is provided in line 642 to a sulfur process unit690, which is this example embodiment is an oxy-Claus unit. A carbondioxide solvent stream is provided in line 693 to the sulfur separationsystem 600, and the sulfurous product in line 642 thus can include acontent of carbon dioxide. The oxy-Claus unit 690 can be adapted to orconfigured to provide a sulfur recovery of greater than 90%, greaterthan 95%, or greater than 99% on a molar basis. To this end, the desiredconcentration of the sulfurous material present in the sulfurous productstream in line 642 can be converted into liquid elementary sulfur as aby-product and removed in line 691. A portion of recovered carbondioxide can be liquefied and recycled in line 693 to the sulfurseparation system 600. A portion of the carbon dioxide may be exportedin line 692 for sequestration and/or used for EOR and/or used for otherchemical processes. The heat Q generated from the oxy-Claus unit 690 canbe used for power generation in power unit 699 or other chemicalprocesses. The oxy-Claus unit 690 can be adapted to or configured tocombined oxygen with hydrogen sulfide to produce elemental sulfur andwater according to the following reaction:

2H₂S+O₂=2S+2H₂O+heat.

The system and method thus can require input of oxygen in line 698 afrom an oxygen source 698 and can output heat Q, which can be utilizedfor power generation, along with elemental sulfur, water, and carbondioxide products (the carbon dioxide being recycled from the content ofcarbon dioxide that was present in the original liquid bottom stream).

In one or more embodiments, the present disclosure can encompassessystems and methods wherein a multi-component feed stream including asulfurous material is contacted with a solvent comprising liquid carbondioxide, and oxy-gas combustion plus flue gas desulfurization arecarried out. In such embodiments, a multi-component feed streamincluding a sulfurous material can be processed as already describedherein such that the sulfurous material from the multi-component feedstream is separated by the liquid carbon dioxide and removed as a liquidbottom product and a gaseous product that is substantially free of thesulfurous material is removed as an overhead vapor stream. As shown inFIG. 7 , a multi-component feed stream including a sulfurous material isinjected in line 705 into a sulfur separation system 700 that mayinclude any combination of parts as otherwise described herein toprovide for separation of at least a portion of the sulfurous materialfrom the multi-component feed stream. A substantially purified gaseousproduct is thus provided in line 725, and sulfurous product is providedin line 742 to an oxy-sulfur burner 790. A carbon dioxide solvent streamis provided in line 793 to the sulfur separation system 700, and thesulfurous product in line 742 thus can include a content of carbondioxide. The sulfurous product and carbon dioxide in line 742 is sent tothe oxy-sulfur burner 790 along with oxygen in line 798 a from an oxygensource 798 to fully oxidize the sulfur species (e.g., to form SO₂ andSO₃). The combustion flue gas (which typically will comprise CO₂, H₂O,SO₂, and SO₃) can be sent in line 790 a to a flue gas desulfurizationunit 797 with limestone injection through line 797 a, and sulfur can beseparated from the flue gas in the form of gypsum through line 797 b, aswell as water in line 797 c. A portion of cleaned carbon dioxide can beliquefied and recycled through line 792 for use as otherwise describedabove. The heat Q generated from the oxy-sulfur burner 790 can be usedfor power generation (e.g., in a steam cycle power generation unit 796)or other chemical processes.

In one or more embodiments, the present disclosure can encompassessystems and methods wherein a multi-component feed stream including asulfurous material is contacted with a solvent comprising liquid carbondioxide, and oxy-gas combustion plus wet sulfuric acid processing arecarried out. In such embodiments, a multi-component feed streamincluding a sulfurous material can be processed as already describedherein such that the sulfurous material from the multi-component feedstream is separated by the liquid carbon dioxide and removed as a liquidbottom product and a gaseous product that is substantially free of thesulfurous material is removed as an overhead vapor stream. As shown inFIG. 8 , a multi-component feed stream including a sulfurous material isinjected in line 805 into a sulfur separation system 800 that mayinclude any combination of parts as otherwise described herein toprovide for separation of at least a portion of the sulfurous materialfrom the multi-component feed stream. A substantially purified gaseousproduct is thus provided in line 825, and sulfurous product is providedin line 842 to a sulfuric acid processing unit 890. A carbon dioxidesolvent stream is provided in line 893 to the sulfur separation system800, and the sulfurous product in line 842 thus can include a content ofcarbon dioxide. The sulfurous product and carbon dioxide is then sent tothe wet sulfuric acid process unit 890 where it is combined with oxygenin line 898 a from an oxygen source 898 to produce concentrated sulfuricacid in line 895. Sulfur can be removed from a gaseous carbon dioxidestream in the form of liquid phase, which includes concentrated sulfuricacid. A portion of cleaned carbon dioxide can be liquefied and recycledin line 893 and/or exported for use as already descried above. The heatQ generated from the process can be used for power generation in powerunit 896 or other chemical processes.

In one or more embodiments, the present disclosure can encompassessystems and methods wherein a multi-component feed stream including asulfurous material is contacted with a solvent comprising liquid carbondioxide, and mineral carbonation processing is carried out. In suchembodiments, a multi-component feed stream including a sulfurousmaterial can be processed as already described herein such that thesulfurous material from the multi-component feed stream is separated bythe liquid carbon dioxide and removed as a liquid bottom product and agaseous product that is substantially free of the sulfurous material isremoved as an overhead vapor stream. The liquid bottom productcomprising carbon dioxide and the sulfurous material is then elevated inpressure (e.g., to about 120 bar) and sent to a heater. The heater canbe maintained at a temperature of approximately 120° C. via combustionof a portion of the product gas under either oxy or air firedconditions. The heated and pressurized bottom stream including carbondioxide and the sulfurous material can be reacted with hematite eitherabove or below grade. The reaction results in the formation of compoundssuch as solid phase pyrrhotite, mascarite, and/or pyrite. The resultingchemistry can be disposed of in place or exploited for commercial use.

EXAMPLE

An example embodiment of a system and method for separation of asulfurous material from a multi-component feed stream is described belowin relation to FIG. 4 . The examiner embodiment particularly relates tothe separation of hydrogen sulfide from a sour natural gas stream. It isunderstood, however, the components used in the system described belowand process steps used in the method described below may be applied inany combination (or be specifically excluded) from systems and methodsas otherwise described herein for separation of other sulfurousmaterials from natural gas or other multi-component feed streams.

Specific process conditions for the removal of hydrogen sulfide, carbondioxide, and C₃ and greater hydrocarbons from a sour natural gas streamare calculated below based upon an example natural gas stream source 18,which comprises (on a molar basis) 65% CH₄, 6.5 C₂H₆, 3% C₃H₈, 0.46%nC₄H₁₀, 0.54% iC₄H₁₀, 0.4% C₅H₁₂, 0.1% C₆H₁₄, 16% H₂S, and 8% CO₂. Thenatural gas stream source 18, at a temperature of about 30° C. and apressure of about 42 bar and saturated with water vapor, is cooled toabout 5° C. in heat exchanger 1 exiting in line 19. The first coolednatural gas stream in line 19 is passed through a separator 2, and acondensed water and residual condensable heavy hydrocarbons stream isremoved from separator 2 in line 20 while a saturated feed gas stream isprovided in line 21. The saturated feed gas stream in line 21 is driedto a dew-point of about −60° C. or lower in a desiccant drier 3 (e.g., adual bed desiccant drier package), which is thermally regenerated usinga nitrogen stream with nitrogen inlet line 22 a and nitrogen outlineline 22 b.

The dried natural gas stream exits the desiccant drier 3 in line 27 fordelivery to a counter-current, multi-stage vapor/liquid contacting firstdistillation column 10, which is provided with two sections ofcontactors (23 and 24), which can be either trays or structured packing.The first distillation column 10 is provided with a re-boiler heatexchanger 17, which boils part of the column bottom liquid stream inline 25 providing a partially vaporized outlet stream in line 26, whichis returned to the base of the first distillation column 10. Optionally,the heating duty in the reboiler heat exchanger 17 can be provided bydiverting at least a portion of the dried crude natural gas feed streamin line 27 to the reboiler heat exchanger as inlet stream 27 a andoutlet stream 27 b, which is re-inserted into line 27.

Prior to entry into the first distillation column 10, the dried naturalgas feed stream 27 is cooled in heat exchanger 7 to a temperature ofabout −50° C. to provide a cooled natural gas feed stream in line 28which enters the first distillation column between the two separationsections 23 and 24. The heat exchanger 7 is also utilized to cool thecarbon dioxide solvent stream in line 29, which is at a pressure ofabout 67 bar and a temperature of about 30° C. The carbon dioxidesolvent stream is cooled to a temperature of about −50° C., and thepressure of the carbon dioxide solvent stream is reduced to about 41 barby expansion across valve 30 before entering the first distillationcolumn 10 in line 31 above separation section 23.

Within the first distillation column 10, downward flowing liquid solventfrom line 31 contacts upward flowing vapor from line 28 to form anoverhead product gas stream 32 at a temperature of about −56° C., theoverheat product gas stream preferably containing a maximum of about 2ppm hydrogen sulfide and more preferably less than 1 ppm hydrogensulfide. The liquid bottom stream in line 25 branches in line 33 toprovide a liquid stream at a temperature of about −46° C., which isremoved from the base of the first distillation column and containssubstantially all of the hydrogen sulfide and C₂ and greaterhydrocarbons present in the natural gas feed stream 18.

The content of carbon dioxide in the overhead vapor stream in line 32can be minimized by reducing the temperature of the solvent stream 31 asmuch as possible without reaching the freezing temperature of the carbondioxide therein. It may be desirable (e.g., when the hydrogen sulfideconcentration is high) to minimize the amount of reflux liquid carbondioxide that is fed to the first distillation column. This can beaccomplished by removing heat simultaneous to the mass transfer from oneor two stages in the first distillation column 10 above the sour naturalgas feed point in line 31 in order to provide refrigeration to promotethe condensation of the hydrogen sulfide rather than rely onrefrigeration provided from the carbon dioxide reflux stream. As anon-limiting example, a suitable contacting device is an aluminumplate-fin heat exchanger with two sets of passages. The first containsan evaporating liquid carbon dioxide stream at a pressure that allowsheat transfer from the distillation stage. The second introducesdown-flowing liquid from the stage above and up-flowing gas from thestage below into a two phase distributor at the base of each passage sothat the mixed vapor and liquid can flow upwards into a separator thatfeeds the equilibrated gas and liquid streams back into the column.

In some embodiments, a significant reduction in the carbon dioxidecontent of the gas stream 38 entering the separation unit 4 can beachieved by processing the overhead vapor stream from the firstdistillation column 10 to remove excess carbon dioxide. This can ensurethat a single stage membrane unit can be used to produce the finalpurified natural gas stream 41 containing 2% carbon dioxide. This isachieved by taking a carbon dioxide permeate stream in line 40 from themembrane carbon dioxide separator 4, compressing in compressor 5,cooling in heat exchanger 6 (to provide the stream in line 29) andfurther cooling in heat exchanger 7 to provide the stream in line 53,which is feed into a third distillation column 50. The thirddistillation column 50 is equipped with a reboiler 51. Line 54 for thebottom product stream branches to line 54 a to deliver bottom productliquid to the reboiler, and the liquid bottom product returns to thethird distillation column in line 54 b. Heat fluid inlet line 90 a andheat fluid outlet line 90 b can deliver any suitable heating stream tothe reboiler 51. The third distillation column 50 can be configured tostrip most of the methane from the permeate stream leaving the singlestage membrane unit 4 giving a bottoms liquid product carbon dioxidestream 54 containing about 5% molar of a mixture of methane and ethaneat a pressure of about 41 bar and a temperature of about −1° C. A netcarbon dioxide product stream in line 80 can be taken from the liquidcarbon dioxide stream in line 54. The overhead stream in line 55 leavingthe third distillation column 50 at a pressure of about 41 bar and atemperature of about −52° C. is heated in the heat exchanger 7 to about25° C. to exit in 56 and merge with the gas stream in line 38 enteringthe carbon dioxide separation membrane unit 4.

Refrigeration duty to the heat exchanger 7 that is used to cool theliquid carbon dioxide-containing solvent and the feed natural gas steamsentering the first distillation column 10 to the required temperaturelevels and to heat exchange other streams can be provided using a closedcycle refrigeration loop that preferably utilizes carbon dioxide as therefrigerant. As seen in FIG. 4 , first and second evaporating liquid CO₂streams in lines 41 and 42 at about −53° C./6 bar and about 2° C./36 barpass to the heat exchanger 7 and are injected back into therefrigeration system 8 in lines 62 and 63. Any suitable refrigerationsystem can be utilized. For example, the refrigeration system 8 caninclude a recycle compressor and inter-stage water coolers.

The overhead vapor stream in line 32 exiting the first distillationcolumn 10 can be at a pressure of about 41 bar and have substantiallythe following composition (on a molar basis): 80% CH₄; 0.9% C₂H₆; 18.39%CO₂; and 1.0 ppm H₂S. The overhead vapor stream in line 32 is heated inheat exchanger 7 to about 25° C. to form the stream in line 38. Toachieve a desirably low concentration of carbon dioxide in the finalnatural gas product stream in line 41, the carbon dioxide separatormembrane 4 can be a single stage membrane system or a multi-stagemembrane system, such as a UOP Separex™ system. In this example, asingle-stage carbon dioxide membrane unit was used which would result ina relatively high hydrocarbon loss in the permeate stream 40 leaving themembrane. A carbon dioxide permeate stream in line 40 can be provided ata pressure of about 1.1 bar and can have the following composition (on amolar basis): 52.2% CH₄; 1.5% C₂H₆; and 46.4% CO₂. The permeate streamin line 40 can be compressed to about 67 bar in the compressor 5 (whichcan be an intercooled compressor) and cooled to about 30° C. in thecooler 6 to provide the stream in line 53, which is delivered to thethird distillation column 50.

The sour natural gas stream in source 18 preferably contains at leastthe quantity of carbon dioxide that may be required for a natural gasproduct stream—e.g., in the range of 2% molar. Any additional carbondioxide in the sour natural gas stream in source 18 above the requiredproduct quantity can be produced as a net product carbon dioxide asalready described above.

The bottom product stream in line 33 exiting the first distillationcolumn 10 can be delivered into a mid-point of a second distillationcolumn 14 equipped with an overhead condenser 15 and a reboiler 16. Inoperation of the second distillation column 12, it can be useful toreduce the pressure of the feed stream in line 33, such as utilizingvalve 86, to a pressure in the range of about 15 bar to about 45 bar toensure that the separated hydrogen sulfide is in the vapor phase and toincrease the relative volatility of the hydrogen sulfide to thehydrocarbon components. Operating in such a reduced pressure range canbe useful to improve the relative volatility of ethane and otherconstituents of the mixture and promote the separation of ethane fromthe sulfurous material. Heat fluid inlet line 92 a and heat fluid outletline 92 b can deliver any suitable heating stream to the reboiler 16.The second distillation can be adapted to or configured to produce anoverhead vapor stream in line 34 at a pressure of about 40 bar and atemperature of about −39° C., the overhead vapor stream containingsubstantially all of the carbon dioxide separated from the bottomproduct stream in line 33 with less than 2 ppm of hydrogen sulfide andless than 100 ppm of a mixture of C₃H₈ and C₄H₁₀. The seconddistillation can be adapted to or configured to produce a bottom productliquid stream in line 35 that contains less than 2% (molar) carbondioxide. The substantially complete separation of the hydrogen sulfidestream can be assisted by the injection through line 57 of a recyclestream containing light naphtha (e.g., including predominantly C₄ to C₆hydrocarbons), the injection being to an intermediate reflux point abovethe inlet feed point for the stream of line 33. The overhead vaporstream in line 34 can have the following composition (on a molar basis):60.2% CH₄; 11.7% C₂H₆; and 28.1% CO₂. The overhead vapor stream in line34 merges with the overhead vapor stream in line 55 leaving the thirddistillation column 50 and is then heated in heat exchanger 7 to about25° C., leaving the heat exchanger 7 in line 56. Optionally, theoverhead vapor stream in line 34 may be compressed in compressor 85prior to mixing with the stream of line 55. The mixed overhead vaporstreams in line 56 are then added to the top product stream in line 32from the first distillation column 10 to provide the membrane inletstream in line 38. Optionally, the stream in line 34, which containsabout 91.7% (molar) of the ethane in the sour natural gas source stream18, can be processed to separate an ethane product by first removing thebulk of the carbon dioxide at about 25° C. with a polymeric membraneunit followed by a distillation column to separate a substantially pureethane stream as a liquid product from the column base and a CH₄+CO₂product overhead, which is recycled as described.

The bottom liquid product stream in line 35 exiting the seconddistillation column 14 can have the following composition (on a molarbasis): 1.0% C₂H₆; 34.5% C₃H₈+C₄H₁₀; 63.4% H₂S; and 1.1% CO₂. The streamin line 35 enters the mid-point of a fourth distillation column 12equipped with an over-head condenser 11 and a reboiler 13. Heat fluidinlet line 94 a and heat fluid outlet line 94 b can deliver any suitableheating stream to the reboiler 13. Likewise, cooling fluid inlet line 96a and cooling fluid outlet line 96 b can deliver any suitable coolingstream to the condenser 11. The fourth distillation column can beadapted to or configured to separate the feed stream in line 35 into anoverhead vapor stream in line 36 containing substantially all of thehydrogen sulfide and a bottom liquid hydrocarbon stream in line 37containing less than 0.1 ppm hydrogen sulfide. A portion of the bottomliquid hydrocarbon stream in line 37 can be circulated through thereboiler 13.

In operation of the fourth distillation column 12, it can be useful toreduce the pressure of the feed stream in line 35, such as utilizingvalve 39, to a pressure in the range of about 10 bar to about 20 bar toensure that the separated hydrogen sulfide is in the vapor phase and toincrease the relative volatility of the hydrogen sulfide to thehydrocarbon components. It can also be useful to add a hydrocarbonadditive stream rich in C₄ and greater hydrocarbons to an appropriatestage within the fourth distillation column 12 between the condenser andfeed inlet stage. The hydrocarbon additive stream preferably is arelatively low volatility component and can have, for example acomposition as follows (on a molar basis): 1% C₃; 61.1% C₄; 29.8% C₅;and 8.1% C₆. The hydrocarbon additive steam can function as a scrubbingsolvent for the C₃ and greater hydrocarbons present in the feed streamin line 35. Any light naphtha stream can be used; however, a preferredadditive stream will be rich in C₄ and C₅ hydrocarbons.

The top product vapor stream in line 36 exiting the fourth distillationcolumn 12 at a pressure of about 17 bar and a temperature of about 12°C. can have the following composition (on a molar basis): 83.6% H₂S;13.6% C₂H₆; 1.4% CO₂; and 1.4% C₃H₈+C₄H₁₀. The remaining hydrocarboncomponents are present in the bottom liquid product stream exiting thefourth distillation column 12 in line 37 at a temperature of about 118°C., which stream is processed in a standard C₃ to C₆ recovery system 9,which also separates the light naphtha stream, which is recycled in line38 and line 64 to the fourth distillation column and in line 57 to thesecond distillation column 14. In some embodiments, the recovery system9 can comprise one or more distillation columns wherein separation andfractionation of C₃ and greater hydrocarbons can be carried out toprovide a desired blend of hydrocarbons. As illustrated, recovery system9 particularly can comprise a de-propanizer similar to separator 251 inFIG. 3 wherein a purified propane stream and a stream of C₄ and greaterhydrocarbons can be produced. In particular, a the top product stream inline 66 can comprise propane and, optionally, a minor content of C₄ andgreater hydrocarbons (e.g., at least 80%, at least 85%, or at least 90%molar propane). A bottom product stream in line 65 can comprisepredominately C₄ and greater hydrocarbons. It is from line 66 which thelight naphtha stream discussed above can be withdrawn as line 66 a forinput to line 38 and 57.

As discussed above, the presently exemplified system and method operateswith refrigeration provided by a refrigeration system 8, whichpreferably uses carbon dioxide as the working fluid. The heat exchanger7 is provided with two streams of liquid CO₂ refrigeration. In thisexample, the first liquid carbon dioxide stream 41 evaporates at apressure of 6 bar and a temperature of −53° C., and the second liquidcarbon dioxide stream 42 evaporates at a pressure of 37 bar and atemperature of 2° C. The precise evaporating pressure of the carbondioxide refrigerant can depend on the composition and pressure of theinlet natural gas stream. The condenser 15 associated with the seconddistillation column 14 can also be cooled using refrigeration providedby the refrigeration system 8. As illustrated, line 60 branches fromline 41 to deliver liquid carbon dioxide refrigerant to the condenser15, and the return stream in line 61 is combined with line 62. Thecoolant passing in lines 96 a and 96 b for condenser 11 can be, forexample, a chilled brine, which also may provide refrigeration for thefeed natural gas heat exchanger 1. The reboilers 16 and 13 and 17 can beheated, for example, using low pressure steam. In areas where ambienttemperatures are very high and cooling water systems are not availablethen air cooling can be used together with closed circuit refrigerationbased on carbon dioxide and/or propane systems. Note that theperformance of the distillation columns 10, 14, 12 and 50 can be basedon the adjustment of the re-boil and reflux rates by controlling theheating and cooling duties provided.

The foregoing example was modeled based on a dried multi-component feedstream flowrate of 8,000 Kg mols/hr at a pressure of 42 bar and atemperature of 30° C. in line 27, wherein the multi-component feedstream had the following composition (on a molar basis): 65% CH₄; 6.5%C₂H₆; 3.0% C₃H₈; 1.0% C₄H₁₀; 0.4% C₅H₁₂; 0.1% C₆H₁₄; 8.0% CO₂; and 16.0%H₂S. The evaluation also considered a flowrate of 5,596.75 Kg mols/hr ofthe substantially pure natural gas product in line 41 at a pressure of40 bar and a temperature of 30° C. and having the following composition(on a molar basis): 92.9% CH₄; 5.1% C₂H₆; 2.0% CO₂; and 1.0 ppm H₂S. Theevaluation further considered a flowrate of 533.2 Kg mols/hr of netcarbon dioxide product in line 80 from a single stage membraneseparation unit followed by the carbon dioxide purification carried outin column 50 at a pressure of 42 bar and a temperature of 25° C., thecarbon dioxide stream having the following composition (on a molarbasis): 3.1% CH₄; 95.0% CO₂; and 1.9% C₂H₆. The evaluation likewiseconsidered a flowrate of 1531 Kg mols/hr for a sulfur product at apressure of 17 bar and a temperature of 1° C. and having the followingcomposition (on a molar basis): 13.7% C₂H₆; 1.0% C₃H₈; 0.3% C₄H₁₀; 83.6%H₂S; and 1.4% CO₂. The evaluation still further considered a flowrate of1389.1 Kg mols/hr of liquefied petroleum gas in line 37 having thefollowing composition (on a molar basis): 16.9% C₃H₈; 51.6% C₄H₁₀; 24.8%C₅H₁₂; 6.7% C₆H₁₄; and0.1 ppm H₂S. Note that the additive to the secondand third column is a light naphtha stream with a composition of 1% C₃,34% nC₄, 27% iC₄, 30% C₅, and 8% C₆ (on a molar basis) which must beseparated and recycled.

Many modifications and other embodiments of the presently disclosedsubject matter will come to mind to one skilled in the art to which thissubject matter pertains having the benefit of the teachings presented inthe foregoing descriptions and the associated drawings. Therefore, it isto be understood that the present disclosure is not to be limited to thespecific embodiments described herein and that modifications and otherembodiments are intended to be included within the scope of the appendedclaims. Although specific terms are employed herein, they are used in ageneric and descriptive sense only and not for purposes of limitation.

1-31. (canceled)
 32. A method for removing hydrogen sulfide from ahydrocarbon-containing fuel gas, the method comprising: contacting astream of a hydrocarbon-containing fuel gas including hydrogen sulfidewith liquid carbon dioxide; recovering a liquid stream comprising atleast a portion of the hydrogen sulfide; and recovering a gas streamcomprising at least a portion of the hydrocarbon-containing fuel gas.33. The method of claim 32, wherein the contacting is carried out in adistillation column.
 34. The method of claim 32, wherein the stream ofthe hydrocarbon-containing fuel gas further includes one or more ofcarbonyl sulfide, thiol-containing compounds, carbon disulfide, anddisulfide bond-containing compounds.
 35. The method of claim 32, whereinthe liquid carbon dioxide is at one or both of a temperature of about−10° C. to about −55° C. and a pressure of about 7 bar to about 60 bar.36. The method of claim 32, further comprising processing the gas streamcomprising at least a portion of the hydrocarbon-containing fuel througha separation unit configured for removal of at least a portion of anycarbon dioxide present in the gas stream comprising at least a portionof the hydrocarbon-containing fuel.
 37. The method of claim 36, whereinthe separation unit is a membrane separator configured for separatingthe gas stream comprising at least a portion of thehydrocarbon-containing fuel into a product stream comprising thehydrocarbon-containing fuel and a permeate stream comprising at leastcarbon dioxide.
 38. The method of claim 37, wherein the product streamcomprising the hydrocarbon-containing fuel contains less than 2 ppmmolar of hydrogen sulfide.
 39. The method of claim 37, wherein theproduct stream comprising the hydrocarbon-containing fuel contains lessthan 2% molar of carbon dioxide.